12 February 2018

FY18 First half results & business update

2

This investor presentation (“Presentation”) is issued by Cooper Energy Limited ABN 93 096 170 295 (“Cooper Energy” or “COE”).

Summary information: This Presentation contains summary information about Cooper Energy and its activities as at the date of this Presentation and should not be considered to be comprehensive or to

comprise all the information which a shareholder or potential investor in Cooper Energy may require in order to determine whether to deal in Cooper Energy shares. The information in this Presentation is a

general background and does not purport to be complete. It should be read in conjunction with Cooper Energy’s periodic reports and other continuous disclosure announcements released to the Australian

Securities Exchange, which are available at www.asx.com.au.

Not financial product advice: This Presentation is for information purposes only and is not a prospectus under Australian law (and will not be lodged with the Australian Securities and Investments

Commission) or financial product or investment advice or a recommendation to acquire Cooper Energy shares (nor does it or will it form any part of any contract to acquire Cooper Energy shares). It has been

prepared without taking into account the objectives, financial situation or needs of individuals. Before making an investment decision, prospective investors should consider the appropriateness of the

information having regard to their own objectives, financial situation and needs and seek legal and taxation advice appropriate to their jurisdiction. Cooper Energy is not licensed to provide financial product

advice in respect of Cooper Energy shares. Cooling off rights do not apply to the acquisition of Cooper Energy shares.

Past performance: Past performance and pro forma historical financial information given in this Presentation is given for illustrative purposes only and should not be relied upon as (and is not) an indication

of future performance. The historical information included in this Presentation is, or is based on, information that has previously been released to the market.

Future performance: This Presentation may contain certain statements and projections provided by or on behalf of Cooper Energy with respect to anticipated future undertakings. Forward looking words

such as, “expect”, “should”, “could”, “may”, “predict”, “plan”, “will”, “believe”, “forecast”, “estimate”, “target” and other similar expressions are intended to identify forward-looking statements within the meaning

of securities laws of applicable jurisdictions. Indications of, and guidance on, future earnings, distributions and financial position and performance are also forward-looking statements. Forward-looking

statements, opinions and estimates provided in this Presentation are based on assumptions and contingencies which are subject to change without notice, as are statements about market and industry trends,

which are based on interpretations of current market conditions. Forward-looking statements, including projections, forecasts, guidance on future earnings and estimates, are provided as a general guide only

and should not be relied upon as an indication or guarantee of future performance. There can be no assurance that actual outcomes will not differ materially from these forward-looking statements.

Qualified petroleum reserve and resources evaluator: This Presentation contains information on petroleum reserves and resources which is based on and fairly represents information and supporting

documentation reviewed by Mr Andrew Thomas who is a full time employee of Cooper Energy holding the position of General Manager, Exploration & Subsurface, holds a Bachelor of Science (Hons), is a

member of the American Association of Petroleum Geologists and the Society of Petroleum Engineers and is qualified in accordance with ASX Listing Rule 5.41 and has consented to the inclusion of this

information in the form and context in which it appears.

Reserves and Contingent Resources estimates: Information on the company’s reserves and resources and their calculation are provided in the appendices to this presentation.

Investment risk: An investment in Cooper Energy shares is subject to investment and other known and unknown risks, some of which are beyond the control of Cooper Energy. None of Cooper Energy, any

of its related bodies corporate or any other person or organisation guarantees any particular rate of return or the performance of Cooper Energy, nor do any of them guarantee the repayment of capital from

Cooper Energy or any particular tax treatment.

Not an offer: This Presentation is not and should not be considered an offer or an invitation to acquire Cooper Energy shares or any other financial products and does not and will not form any part of any

contract for the acquisition of Cooper Energy shares. This Presentation does not constitute an offer to sell, or the solicitation of an offer to buy, any securities in the United States or to, or for the account or

benefit of, any “U.S. person” (as defined in Regulation S under the US Securities Act of 1933, as amended (“Securities Act”)) (“U.S. Person”). Cooper Energy shares have not been, and will not be, registered

under the Securities Act or the securities laws of any state or other jurisdiction of the United States, and may not be offered or sold in the United States or to any U.S. Person absent registration except in a

transaction exempt from, or not subject to, the registration requirements of the Securities Act and any other applicable securities laws. This document may not be distributed or released in the United States or

to any U.S. person.

Rounding: All numbers in this presentation have been rounded. As a result, some total figures may differ insignificantly from totals obtained from arithmetic addition of the rounded numbers presented.

Currency: All financial information is expressed in Australian dollars unless otherwise specified.

P50 as it relates to costs is best estimate; P90 as it relates to costs is high estimate

Important Notice – Disclaimer

3

3 Key messages

1

2

3

Strong growth in production, cash generation and earnings. Safe operations• zero recordable injury cases and lost time injuries

• 264% growth in half year operating cash flow, 433% growth in underlying EBITDA and 406% growth in production

• production in line for full year guidance of 1.4 MMboe

Sole project advancing within schedule and budget; key milestones imminent • total project 30% complete end-January

• offshore project costs to 31 January within $355 million budget and schedule

• production wells scheduled for drill and complete April and May 2018 (subject to final regulatory approvals for Ocean Monarch drill rig)

The value potential of our existing assets has been upgraded • new Casino Henry gas contract

• south-east Australian gas market: supply tight, consolidation of prices and expectations

• Haselgove-3 discovery has reset value and expectations for our Penola Trough acreage onshore Otway Basin

• geotechnical analysis of offshore Otway Basin has reshaped our exploration plans and views of potential

4

Current position and outlook

Cooper Energy is in the midst of a 6 year growth profile sourced from existing assets and its

leverage to the south-east Australian gas market.

0.271.1

FY18

FY18 production forecastMMboe

Gas

Oil

• Production 1.4 MMboe (incl 6 PJ pa gas)

• Gas contracts with Origin, AGL, EnergyAustralia, Alinta, O-I Australia

• Developing Sole gas project

• Operator in Otway & Gippsland

• 225 PJ Uncontracted gas

• Gas exploration acreage & resources.

0.4

FY16

FY16 production and forecastMMboe

Now:

Suppling & developing

0.25 0.24

1.8

6.0

FY19 FY20

FY19 & FY20 forecast* productionMMboe

2012 – 2016

Vision execution

12 – 24 months:

Delivery & growth

• Production > 6MMboe (over 30 PJ pa from Casino Henry, Otway Basin & Sole, Gippsland Basin)

• Otway Basin development

• Evaluating Manta gas project

• Gas exploration offshore and onshore Otway Basin

Longer term:

Blue sky & potential

• Production >10 MMboe

• Manta gas project

• New offshore Otway gas discovery & development

• New onshore Otway gas discovery & development

5.3

4.9

FY22f

FY22 forecast production **MMboe

0.16

Building a portfolio style gas business creating shareholder value as a cost competitive gas supplier to opportunities foreseen emerging in south-east Australia

competitive position on cost curve

development decision within 5 years foreseeable

value-adding to asset or Cooper Energy

* Indicative and includes Henry development well,

** Indicative includes Henry development well and Manta commencement FY22

5

11

31.3

H1 FY17 H1 FY18

First half sales revenue$ million

• HSEC: zero recordable injury cases and reportable environmental incidents

• Sole gas project FID in August and 30% complete at 31 January

• 2P reserves upgraded 362% from 11.7 million to 54.1 million boe at 25 August 2017

• Regulatory approval for Cooper Energy as operator of offshore operations and projects including Casino Henry, VIC/P44 and Sole

• Orbost Gas Processing Facility transaction completed with APA Group

• Financial Close of $265 million Senior Secured Debt facilities (with ANZ Bank and Natixis) and first draw-down

• Capital raising completed for $135 million

• New supply contract for Casino Henry gas agreed with Origin Energy to commence March 2018 (our 5th term gas contract since August 2015)

• Production increased 417% to 0.8 MMboe from 0.16 MMBoe

• Cooper Basin oil production increased 6%

• Revenue, cash generation and statutory profit all grew 2 to 3 times or more

FY18 First half key outcomes

Gas strategy delivering results in key performance indicators and business development

11.7

54.1

2017 2017 Aug

2P ReservesMMboe

0.16

0.81

H1 FY17 H1 FY18

First half productionMMboe

-3.9

13.0

H1 FY17 H1 FY18

First half EBITDAunderlying $ million

-8.2

19.8

H1 FY17 H1 FY18

Net profit after tax$ million

6

$ million unless otherwise indicated H1 FY18 H1 FY17 change

Production MMbbl 0.81 0.16 ▲ 417%

Sales revenue 31.3 11.0 ▲ 185%

Gross profit 14.1 4.6 ▲ 206%

Gross profit/Sales revenue % 45.0% 41.8% ▲ 8%

Statutory profit before tax 21.3 (5.3) ▲ 502%

Statutory profit/(loss) after tax 19.8 (8.2) ▲ 342%

Underlying EBITDA 13.0 (3.9) ▲ 433%

Underlying profit/(loss) after tax 2.2 (3.5) ▲ 163%

Cash flow from operations 10.0 (6.1) ▲ 264%

31 Dec 17 30 June 17

Borrowings 79.4 - ▲ 100%

Cash 283.2 147.5 ▲ 38%

Net cash (debt) 203.8 147.5 ▲ 92%

Key financial results

7

6 months ending 31 December 2017: $ million

Net profit after tax 19.8

Adjustments for:

Gain on sale of subsidiary (Orbost Gas Processing Facility) -21.9

Gain on movement of consideration receivable -0.4

Gain on derecognition of investment in associate -0.4

Reset of Patricia Baleen restoration provision 4.6

Impairment of exploration & evaluation 0.7

Tax impact -0.2

Underlying net profit after tax 2.2

Statutory and underlying profit

Orbost Gas Processing Facility value addition the major item in reconciliation of statutory to

underlying profit

8

First half underlying NPAT movement

Addition of gas business and higher oil volume and prices the drivers for profit turnaround

1

$ million

Includes,

acquisition &

integration

costs, Tunisian

redundancy

+19.5

+0.5+3.5

+1.3

-12.6

-0.3-0.8 -2.4

-3.0

-3.5

+2.2

-5

0

5

10

15

20

25

FY17 H1 Gas revenue Oil priceimpact

Oil salesvolumeimpact

Cost of Sales Otherrevenue

Explorationw/o

Finance costs(non cash)

Admin andother

Tax impacts FY 18 H1

9

+22.5 -7.2 -2.4 -4.8

+1.8

+0.0

+127.3

+78.4 -82.3

-20.0 +0.6+41.8

-20.0

147.5 157.4

283.2

Jun-17 Operations GeneralAdmin

Restorationcosts

Tax Interest Cash afteroperatingcash flows

Netproceeds

from equityissues

Net debtdrawdowns

E & D Acquistionsof oil & gas

assets

Receiptsfrom

disposal ofproducing

asset

Receiptsfrom

disposal ofPPE

Transfer toescrow

Dec-17

Operating cash flow

+10.0

Financing & investing cash flow

+125.8

Movement in cash

Cash from operations, capital raising and debt draw-down contributed to $136 million increase

10

• TRCFR = 0.0 (FY16 TRCFR = 1.98)

− zero Lost Time Injuries

• Compliance as a new offshore Operator

– HSEC Management Systems: developed and fit-for-purpose

– best practice and compliant Safety Cases, Environment

Plans, Well Operations Management Plans for offshore

operations, together with onshore pipeline equivalents

• Ongoing improvement initiatives program:

– “Care”: a core value

– audits: internal and key contractors

– awareness and training

– a “One Team” culture

Safety

Injury-free. Operator management systems developed and implemented plus ongoing

improvement program driven by value of Care.

2.2.1

2.5

4.2

0.0

1.98

0.00.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

2012 2013 2014 2015 2016 2017 2018 H1

Total Recordable Case Frequency Rateevents per million hours worked

11

Review of operations: offshore Otway Basin

Gas production and marketing for new contracts to supply from March’ 18

First half production H1 FY17 H1 FY18

Sales gas PJ - 3.86

Condensate kbbl - 3

Casino Henry

• sales gas of 3.1 PJ produced (Cooper Energy share)

• Casino 5 shut-in

• new gas contract: Origin Energy from 1 March 2018 to 31 December

2018

• processing at Iona agreed to December 2018

Minerva gas field

• sales gas of 0.7 PJ produced (Cooper Energy share)

• field production exceeding forecast, field life estimates to be re-

estimated

VIC/P44

• reprocessing of 3D seismic nearing completion for refresh of

exploration prospect inventory

12

Sole gas project

• Final Investment Decision

August ‘17

• Sole gas into plant: March ‘19

• $355 million capex of which circa

60% is lump sum contract

• Subsea development; similar to

other Victorian offshore projects

Midstream: APA Group

• undertaking $250 million plant

upgrade to process Sole gas

• operate Orbost Gas Processing

Facility to process Sole gas at

agreed tariff

• provision for Manta and other gas

Upstream: Cooper Energy

New supply for south-east Australia with blue chip customers & uncontracted gas

Enabling customers

Orbost Gas Processing Facility

(APA 100%)

Sole gas field

(Cooper Energy 100%)

Manta gas field

(Cooper Energy 100%)

1 Reserves and Contingent Resources at 25 August 2017 were announced to the ASX on 29 August 2017 The resources information displayed should be read in conjunction with the information provided on the calculation of Reserves and Contingent Resources provided in the appendices to this document. The announcement included recognition of proved and probable reserves for the Sole gas field, the contingent resource for which was previously announced 27 February 2017.

Gas marketing

• 249 PJ 1 2P gas

• Supply: ~24 PJ pa

• 186 PJ contracted to support

financing; 63 PJ to be

marketed later 2018

13

EXISTING PATRICIA

BALEEN PIPELINE

ORBOST GAS PROCESSING FACILITY

Works By - APA GroupPlant Upgrade & Operations

64 km Umbilical

Lay & Buried

HDD – Umbilical

Crossing

Casing Size 10”

Casing Length – 1.1 km

HDD Gas Pipeline Crossing

Hole Drill Size – 24”

12” Pipeline Length – 1.4 km

OFFSHORE DRILLING &

CONSTRUCTION

Works By - Cooper Energy

HDD Crossing, Drilling &

Completions, Subsea

Infrastructure installation

65 km - 12” Gas

Pipeline Reel Laid

Sole 3 – Tree &

Wellhead System

Sole 4 – Tree &

Wellhead System

1 x Pipeline End

Manifold

1 x Umbilical Subsea

Termination Unit with

jumpers to wells

Sole Drill Centre Water Depth – 125m

Two Horizontal “Christmas” Tree

Drill Measured Depth – 2 x ~1200m

Sole gas project

30% complete to end-January 2018

65 km pipe received and stored at

Hastings, Victoria

Subsea tree #1 complete and

on board Ocean Monarch.

Tree #2 complete and shipped

to Melbourne Mar ‘18

Completed umbilical bell mouth on

sea bed

Umbilical spooling, UK. Umbilical 70%

complete

Piling completed

Plant construction contract

awarded.

HDD – Horizontal Directionally Drilled

14

H1 FY18 H2 FY18 H1 FY19 H2 FY19

Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun

Phase EXECUTE OPERATE

Subsurface Subsurface Team Support for Well Planning Ops Geology Support Reservoir and Production Engineering

WellsDetailed Well Planning & Rig Contracting Drill & Complete

Procurement (Xmas Trees, Casing, Tubing etc.)

Pipeline

Offshore Pipeline Fabrication & Transport Spool Base Fabrication

Umbilical Detailed Design, Fabrication

Earthworks and pipeline shore crossing

Subsea

Installation

Pipeline

Transport/Install

Umbilical & Tie In

Onshore

Plant Detailed Design

Deconstruct and Piling Construction & Pre-Commissioning

Procurement Equipment and Bulks & Delivery on site

Phase 1 CommissioningPhase 2

Commissioning

Perf

Test

HSEC Rig Safety Cases, Well Operations Management Plans, Construction Management Plans Operations Safety Case & Mgt Plan

Sole gas project schedule – as at 31 January 2018

On track for first gas to plant in March 2019

15

Offshore drilling program schedule* as at 31 January 2018

Location Project March April May June July

Otway Casino-5 workover

Gippsland

Sole-3

drill & complete

Sole-4

drill & complete

Sole-2 abandonment

BMG abandonmentPhase-1

Expect to commence March*, Sole production wells scheduled for completion by May

First phase

• Diamond Offshore Ocean Monarch expected to depart Fremantle for Otway Basin in February* 2018

• March: Casino-5 workover

• April: Sole-3 production well drill and complete

• May: Sole-4 production well drill and complete

• June: Sole-2 abandonment

• June-July: BMG abandonment (first phase)

*Subject to regulatory approval for Diamond Offshore MonarchDiamond Offshore Ocean Monarch

16

South Australia

• Haselgrove-3 discovery in adjoining PPL 62 has confirmed

conventional gas prospectivity of the Sawpit sandstone at depths

below previous producing levels

• SA government grant to PEL 494 JV (Cooper Energy 30% interest)

of $6.9 million awarded to drill Dombey-1 gas exploration well.

Expected FY19.

Victoria

• Prospectivity of Penola Trough acreage upgraded by Haselgrove-3

discovery

• Cooper Energy to assume 100% of PEP 171 on government

ratification

• Exploration permits in Victoria subject of application to suspend

and extend due to state government moratorium on onshore gas

production

Otway Basin, Penola Trough onshore

Haselgrove drilling results confirm prospectivity for deep conventional gas

17

• First half production of 137 kbbl vs 130 kbbl in pcp

– connection of Callawonga wells drilled FY17

• Average realised price: A$74.51/bbl for H1 FY18

• Operating costs of A$32.40/bbl for H1 FY18

• 2 exploration wells plugged and abandoned

• No further drilling planned for FY18

Review of operations Cooper Basin

Low cost, cash-generating oil production

66.362.0

63.5

75.2

0

20

40

60

80

100

120

140

H1 FY17 H1 FY18

Cooper Energy Cooper Basin oil productionKbbl

Q2

Q1

18

ACCC view of supply and pricing for south-east Australian gas

464

348

40

Southern states' demand Southern states'production

Southern states* gas demand & supply balance

2018 PJ

* Excludes Cooper Basin Source: ACCC Gas Inquiry 2017- 2020

Interim Report December 2017

Forecast southern

production shortfall

116 - 156 PJ

Forecast gas demand exceeds forecast local production

…necessitating supply from northern fields…

…the delivered cost of which is the price benchmark, which will be affected by oil & LNG prices

“While the currently expected supply-demand balance in the Southern States continues, these

delivered gas prices would be expected to shape the market price of gas in the Southern States” ACCC: Gas Inquiry 2017-2020

Demand

Centre

Transportation

ex- Wallumbilla

Delivered prices using

benchmark range

Adelaide 1.85 7.72 - 9.70

Sydney 2.07 7.94 - 9.92

Melbourne 2.45 8.32 - 10.30

Gas flows

Delivered 2018 gas prices A$/GJ at southern demand

centres based on Queensland benchmark prices

Source: ACCC Gas Inquiry 2017- 2020 Interim Report December 2017 –

which assumes US$6/mm Btu to US$7.50/mm Btu Asia LNG price

19

Cooper Energy contracted and uncontracted gas profile*Indicative production profile from Casino Henry, Sole and Manta

Note

1. Assumes:

• Sole proceeds to schedule for March quarter 2019 first Sole gas to plant

• Manta 3 appraisal well

• Casino Henry development well FY19

• No new exploration success

2. All numbers rounded

* Comprises 56 PJ 2P Casino Henry gas and 249 PJ 2P Sole gas and 117 PJ from Manta. Profile illustrated includes additional 11 PJ risked prospective resource anticipated from Manta. Cooper Energy announced Manta Contingent and Prospective Resource 16 July 2015. Cooper Energy is not aware of any new information or data that materially affects the information provided in those releases and all material assumptions and technical parameters underpinning the assessment provided in the announcement continues to apply.

63

14

20 20 20 20 20 20 2016

13

4

7

2113

3634 33

25

1511

14

12

3

FY18 FY19 FY20 FY21 FY22 FY23 FY24 FY25 FY26 FY27 FY28 FY29 FY30

Gas sales from current assetscontracted & uncontractedPJ pa

Uncontracted

Contracted

20

FY18 first half wrap-up

Gas strategy gains flowing through, Sole on track, milestones approaching

FY18 first half results show gains from gas strategy delivery

• Value addition from Orbost Gas Processing Facility

• Substantial uplift to production, revenue, earnings and cash generation from addition of gas business and higher oil prices

Delivery of key milestones for gas strategy and Sole gas project

• APA agreement, Sole FID, Senior Secured debt facilities

• Casino Henry gas contracts

Sole on track with key drilling milestones in coming months

• Sole gas project proceeding to schedule for gas to plant March 2019 and within budget of $355 million

Gas market: south-east Australia supply outlook is tight and prices favourable for the competitive suppliers

• South-east Australia gas market and outlook continues to offer prices and demand that reward cost competitive supply from south-east Australia

Exploration portfolio: more opportunities and value upgraded

• Offshore Otway Basin gas

• Onshore Otway Basin gas upgraded by Haselgrove discovery

Balance of FY18 features catalysts for derisking, for value and for commercial activities

• Production well completion to close out variable cost element of $355 million Sole project cost and significantly derisk project

• Plan to commence marketing of Sole uncontracted gas and review potential Gippsland JV partners after Sole wells

Appendices

22

Cooper Energy - assets

Portfolio built around winning position on cost curve

Key statistics*

Proved & Probable Reserves 54.1 MMboe

Contingent Resources (2C) 34.9 MMboe

Production FY18 guidance 1.4 MMboe

Market capitalisation $512 million

Net cash/(debt) $203.8 million

Issued share capital (million) 1,601.1

• Casino Henry gas project

• Minerva gas project

• Exploration acreage

Offshore Otway Basin

• Sole gas project

• Manta gas

Gippsland Basin

Cooper Basin

Oil production & exploration

• Gas exploration acreage

Onshore Otway Basin

1.7

9.7

42.7

Proved & Probable Reserves54.1 MMboe

Cooper Basin oil

Otway Basin gas andgas liquids

Gippsland Basin gas

* As at 31 December 2017; except for reserves and resources (as at 25 August 2017 and market capitalisation and issued share capital (9 February 2018)

23

Cooper Energy portfolio: focussed on south east Australia

305 PJ 2P and 158 PJ 2C gas and exploration acreage located close to market and infrastructure

Otway18663

139

10

4619

2P Reserves contracted

2P Reserves uncontracted

2C Contingent resources uncontracted

Gippsland Basin: gas development

• Sole gas project 249 PJ 2P gas being developed

for mid-2019 start up

• 63 PJ 2P uncontracted to be marketed in 2018

• Manta gas and liquid resource ready for drilling

and development decision 2019

Offshore Otway Basin:

Gas production and exploration

• 2018 production fully contracted to Origin Energy

• 46 PJ uncontracted to supply from 2019-on

• Minerva gas plant

• Prime gas exploration acreage with favourable economics

1 Reserves and Contingent Resources at 25 August 2017 were announced to the ASX on 29 August 2017. The resources information displayed should be read in conjunction with the information provided on the calculation of Reserves and Contingent Resources provided in the appendices to this document. The announcement included recognition of proved and probable reserves for the Sole gas field, the contingent resource for which was previously announced 27 February 2017. The contingent resource estimate for the Manta resource was announced to the ASX on 16 July 2015.

Cooper Basin: oil production

• historical production source

• production of 250 kbbl oil pa

• low cost operations

Onshore Otway Basin: gas exploration

• gas exploration acreage

• extends over Sawpit sandstone fairway

and surrounds Haselgrove discovery

24

South-east Australia1 gas supply costs in 2020*

Cooper Energy projects are cost competitive for south-east Australia

Source: EnergyQuest

• Delivered Melbourne city gate gas cost in 2017 AUD based on economic upstream cost (including acceptable return) and pipeline charge

• Average daily volume determined by upstream reservoir & facilities capacity and taking account of pipeline capacities, from known gas reserves and resources with access

to infrastructure and anticipated to be available in 2020/21

• Excludes gas that may be available from storage

Delivered Melbourne city gate cost for gas from eastern Australia available for delivery to domestic market in 2020*AUD / GJ

1 South-east Australia comprises New South Wales, Victoria, South Australia and Tasmania 2 Cooper Energy estimate. Represents 75% percentile of 2016 daily gas flows

0

2

4

6

8

10

12

14Casino-Henry

Speculant-Halladale

GBJV - incl. Kipper

Thylacine-Geographe

Sole-Manta

Cooper Basin

All QLD CSG - incl. LNG

Amadeus

Yolla

Blacktip

Beetaloo

Petrel-Tern

Gas available for supply to Victoria, New South Wales, South Australia and Tasmania 2020 (TJ/day)

500 1,000 1,500

Sole - Manta

Typical peak daily quantity for

VIC/NSW/SA/TAS (2016)2

Average daily quantity for

VIC/NSW/SA/TAS (2016)

* Note: all estimates are as calculated by EnergyQuest and based on known capital expenditure to date, which may exceed cost to the current project owner(s).

Casino- Henry

25

6 3

-

5 11 9 7 5 4 3 1

14 2020

2020 20

2020

1613

4

2

10 4 4

4 4 4

4 4

8 11

3

26 25

25

18

10

7 5 1

FY18 FY19 FY20 FY21 FY22 FY23 FY24 FY25 FY26 FY27 FY28 FY29 FY30

Gas sales profile by project contracted & uncontracted PJ pa

Manta uncontracted

Sole uncontracted

Sole contracted

Otway uncontracted

Otway contracted

Cooper Energy contracted and uncontracted gas profile* by project

Existing assets & projects offer growth over 5 years before exploration

Indicative and assumes:

• Sole proceeds to schedule for March quarter 2019 first Sole gas to plant

• Manta 3 appraisal well

• Development well required for Casino Henry FY19

• No new exploration success

All numbers rounded.

Gippsland Gas Project

Phase 1

Sole

Gippsland Gas Project

Phase 2

Manta

* Profile is indicative and comprises 56 PJ 2P Casino Henry gas and 249 PJ 2P Sole gas and 116 PJ from Manta. Profile illustrated includes additional 11 PJ Risked Prospective resource anticipated from Manta. Cooper Energy announced Manta Contingent and Prospective Resource 16 July 2015. Cooper Energy is not aware of any new information or data that materially affects the information provided in those releases and all material assumptions and technical parameters underpinning the assessment provided in the announcement continues to apply.

Otway 2P reserves:

Casino Henry

26

Forecast eastern Australia gas supply and demand outlook

Tight market forecast* for 2018 and 2019

1913

662

20

-318

642

1,217

338

Production Export LNGdemand

Supplyavailable for

domesticmarket

Expecteddemand

Residualsupply LNGbase case

1921

628

30

-281

598

1,293311

Production Export LNGdemand

Supplyavailable for

domesticmarket

Expecteddemand

Residualsupply LNGbase case

598

Supply shortfall @

max LNG

production

2018

PJ

* Source: ACCC Gas Inquiry 2017 - 2020 Interim Report December 2017 ACCC using AEMO Expected Domestic Demand

LNG base

case=

contract +

forecasts

spot sales

Additional demand

@ max capacity

LNG

Supply shortfall @

max LNG

production

2019

Range of ACCC 2018

Supply demand balance

between base case and

max LNG demand

Range of ACCC 2019

Supply demand balance

between base case and

max LNG demand

PJ

27

Offshore Otway Basin prospectivity

Attractive prospectivity & extensive acreage in lightly explored gas province

Four offshore production wells producing via pipeline to shore

Gas sold at Iona gas plant

Remaining 2P 56 PJ1

Current Status

1,197 km2 under licence offshore

No wells drilled since 2008

Large prospect inventory identified in VIC/P44; /RL11 & 12 and /L24 & 30

Underexplored

High quality 3D seismic

Structures clearly identified

Seismic amplitude reliable guide to presence of gas

6 of 7 exploration wells in greater area drilled on 3D seismic amplitude found gas

Technical merit & success rates

Proximity to market and infrastructure offers supportive economics

Low cost subsea tiebacks

Low development threshold

1 Reserves and Contingent Resources at 30 June 2017 were announced to the ASX on 29 August 2017 The resources information displayed should be read in conjunction with the

information provided on the calculation of Reserves and Contingent Resources provided in the appendices to this document.

28

Sole gas project

• FID 29 August 2017

• Sole gas project proceeding to first gas sales mid-2019

Manta

• Secured provision for processing at Orbost Gas Processing Facility under agreement with APA

• Detailed planning to commence

• Economics enhanced by cost discovery from Sole FEED and gas price and demand expectations

Gippsland Basin

Cost competitive resource, existing plant and Sole production planned for FY19

1 Reserves and Contingent Resources at 25 August 2017 were announced to the ASX on 29 August 2017 The resources information displayed should be read in conjunction with the information provided on the calculation of Reserves and Contingent Resources provided in the appendices to this document. The announcement included recognition of proved and probable reserves for the Sole gas field, the contingent resource for which was previously announced 27 February 2017. The contingent resource estimate for the Manta resource was announced to the ASX on 16 July 2015.

Key assets: (all 100% equity & Operator)

• Sole gas project (VIC/L32)

• Manta gas resource (VIC/RL13,14,15)

• Patricia Baleen gas field & associated infrastructure

(VIC/L21)

Reserves & resources1

Sole 2P

Reserves

Manta 2C

Resource

Sales gas PJ 249 106

Condensate MMbbl - 3.2

29

Capex vs PCP Revised Guidance

FY17 H1 FY18 H1 ChangePrior

FY18

Revised

FY18

Cooper Basin 2.1 2.3 0.2 Cooper Basin 6 6

Otway Basin 0.3 3.6 3.3 Otway Basin 35 22

Gippsland Basin 11.0 73.0 62.0 Gippsland Basin 222 222

Other 0.1 0.5 0.4 Other 3 3

Total 13.5 79.4 65.9 Total 266 253

Capital expenditure; incurred and outlook

Revision to FY18 capex expectations brought by timing of Otway Basin development

• Change to Otway Basin guidance reflects movement of development projects including Henry development well and other initiatives to FY19

30

Senior management

General Manager, Operations

Iain MacDougall

Iain MacDougall has more than 28 years

experience in the upstream petroleum

exploration and production sector. His

experience includes senior management

positions with independent operators and

wide ranging international experience with

Schlumberger. In Australia, Iain’s

previous roles include Production and

Engineering Manager and then acting

CEO at Stuart Petroleum prior to the

takeover by Senex Energy.

.

Managing Director

David Maxwell

David Maxwell has over 30 years’

experience as a senior executive with

companies such as BG Group, Woodside

and Santos. As Senior Vice President at

QGC, a BG Group business, he led BG’s

entry into Australia, its alliance with and

subsequent takeover of QGC. Roles at

Woodside included director of gas and

marketing and membership of

Woodside’s executive committee.

General Manager,

Exploration & Subsurface

Andrew Thomas

Andrew Thomas is a successful

geoscientist with over 28 years’

experience in oil and gas exploration

and development in companies

including Geoscience Australia, Santos,

Gulf Canada and Newfield Exploration.

At Newfield he was SE Asia New

Ventures Manager and Exploration

Manager for offshore Sarawak.

Alison Evans is an experienced company

secretary and corporate legal counsel with

extensive knowledge of corporate and

commercial law in the resources and energy

sectors.

Alison has held Company Secretary and Legal

Counsel roles at a number of minerals and

energy companies including Centrex Metals,

GTL Energy and AGL. Ms Evans' public

company experience is supported work at

leading corporate law firms.

Company Secretary &

Legal Counsel

Alison Evans

General Manager, Development

Duncan Clegg

Duncan Clegg has over 35 years’ experience in

upstream and midstream oil and gas

development, including management positions

at Shell and Woodside, leading oil and gas

developments including FPSO, subsea and

fixed platforms developments. At Woodside

Duncan held several senior executive positions

including Director of the Australian Business

Unit, Director of the African Business Unit and

CEO of the North West Shelf Venture.

Eddy Glavas has more than 18 years'

experience in business development,

finance, commercial, portfolio

management and strategy, including 14

years in oil & gas. Prior to joining

Cooper Energy, he was employed by

Santos as Manager Corporate

Development with responsibility for

managing multi-disciplinary teams

tasked with mergers, acquisitions,

partnerships and divestitures.

General Manager, Commercial

& Business Development

Eddy Glavas

Virginia Suttell is a chartered accountant

with more than 20 years' experience,

including 16 years in publicly listed

entities, principally in group finance and

secretarial roles in the resources and

media sectors. This has included the role

of Chief Financial Officer and Company

Secretary for Monax Mining Limited and

Marmota Energy Limited. Other previous

appointments include Group Financial

Controller at Austereo Group Limited.

Chief Financial Officer

Virginia Suttell

General Manager, Projects

Michael Jacobsen

Michael Jacobsen has over 25 years’

experience in upstream oil and gas

specialising in major capital works

projects and field developments.

He has worked more than 10 years with

engineering and construction contractors

and then progressed to managing multi

discipline teams on major capital projects

for E&P companies.

31

Notes on calculation of Reserves and ResourcesNotes on Calculation of Reserves and Contingent Resources

Cooper Energy has completed its own estimation of reserves and resources in accordance with the definitions and guidelines in the Society of Petroleum Engineers (SPE) 2007 Petroleum Resources Management System (PRMS). All reserves and contingent resources figures in this document are net to Cooper Energy.

Petroleum Reserves and Contingent Resources are prepared using deterministic and probabilistic methods based on information provided by the permit Operators Beach Energy Ltd, Senex Ltd, Santos Ltd, and BHP Billiton Petroleum (Victoria) P/L. Cooper Energy undertook the following analytical procedures to estimate the Reserves: independent interpretation of 3D seismic data; analysis of historical production data to assess accessed gas volumes and future production forecasts; review of the Operator’s reservoir and production simulation models to define raw gas recovery consistent with existing processing facilities; and independent probabilistic Monte Carlo statistical calculations to establish the range of recoverable gas. The resources estimate methodologies incorporate a range of uncertainty relating to each of the key reservoir input parameters to predict the likely range of outcomes.

Project and field totals are aggregated by arithmetic summation by category. Aggregated 1P and 1C estimates may be conservative, and aggregated 3P and 3C estimates may be optimistic due to the effects of arithmetic summation. Totals may not exactly reflect arithmetic addition due to rounding.

The information contained in this report regarding the Cooper Energy reserves and contingent resources is based on, and fairly represents, information and supporting documentation reviewed by Mr Andrew Thomas who is a full-time employee of Cooper Energy Limited holding the position of General Manager Exploration & Subsurface, holds a Bachelor of Science (Hons), is a member of the American Association of Petroleum Geologists and the Society of Petroleum Engineers, is qualified in accordance with ASX listing rule 5.41, and has consented to the inclusion of this information in the form and context in which it appears.

Reserves

Under the SPE PRMS, reserves are those petroleum volumes that are anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves at 25 August 2017 were announced to the ASX on 29 August 2017. The Otway Basin totals comprise the arithmetically aggregated project fields (Casino-Henry-Netherby and Minerva) and exclude reserves used for field fuel. The Cooper Basin totals comprise the arithmetically aggregated PEL 92 project fields and the arithmetic summation of the Worrior project reserves, and exclude reserves used for field fuel. The Gippsland Basin total comprise Sole field only and is net of fuel gas.

Contingent Resources

Under the SPE PRMS, contingent resources are those petroleum volumes that are estimated, as of a given date, to be potentially recoverable from known accumulations but for which the applied projects are not considered mature enough for commercial development due to one or more contingencies.

The Contingent Resources at 25 August 2017 assessment includes resources in the Gippsland, Otway and Cooper basins and were announced to the ASX on 29 August 2017Cooper Energy is not aware of any new information or data that materially affects the information provided in those releases, and all material assumptions and technical parameters underpinning the estimates provided in the releases continue to apply.

32

$, A$ Australian dollars unless specified otherwise

Bbl barrels of oil

Boe barrel of oil equivalent

EBITDA earnings before interest, tax, depreciation and amortisation

FEED Front end engineering and design

kbbls thousand barrels

m metres

MMbbl million barrels of oil

MMboe million barrels of oil equivalent

NPAT net profit after tax

PEL 92 Joint Venture conducting operations in Western Flank Cooper Basin Petroleum Retention Licences 85 – 104 previously encompassed by

the PEL 92 exploration licence

PEL 93 Joint Venture conducting operations in Cooper Basin Production Licence 207

TRCFR Total Recordable Case Frequency Rate. Recordable cases per million hours worked

1P reserves Proved reserves

2P reserves Proved and Probable reserves

3P Proved, Probable and Possible reserves

1C, 2C, 3C high, medium and low estimates of contingent resources

Abbreviations